Enhancing hydrocarbon recovery

ABSTRACT

Recovery of hydrocarbon fluid from low permeability sources is enhanced by introduction of a treating fluid. The treating fluid may include one or more constituent ingredients designed to cause displacement of hydrocarbon via imbibition. The constituent ingredients may be determined based on estimates of formation wettability. Further, contact angle may be used to determine wettability. Types and concentrations of constituent ingredients such as surfactants may be determined for achieving the enhanced recovery of hydrocarbons.

CROSS-REFERENCE TO RELATED APPLICATION

This application is related to commonly-assigned and simultaneously-filed U.S. patent application Ser. No. ______, entitled “Method of Hydrocarbon Recovery”, incorporated herein by reference in its entirety.

FIELD OF THE INVENTION

The Invention is generally related to hydrocarbon recovery from low permeability sources.

BACKGROUND OF THE INVENTION

Recovering hydrocarbons such as oil and gas from high permeability reservoirs is well understood. However, recovery of hydrocarbon resources from low permeability reservoirs is difficult and less well understood. Consequently, operators have until recently tended to bypass low permeability reservoirs such as shales in favor of more conventional reservoirs such as sandstones and carbonates. A shale reservoir typically includes a matrix of small pores and may also contain naturally occurring fractures/fissures (natural fractures). These natural fractures are most usually randomly occurring on the overall reservoir scale. The natural fractures can be open (have pore volume) under in-situ reservoir conditions or open but filled in with material (have very little or no pore volume) later in geologic time; for example, calcite (CaCO₃). These fractures can also be in a closed-state (no pore volume) due to in-situ stress changes over time. Natural fractures in any or all of these states may exist in the same reservoir. For more complete understanding of the occurrence, properties, behavior, etc. of naturally fractured reservoirs in general, one may review the following references: Nelson, Ronald A., Geologic Analysis of Naturally Fractured Reservoirs (2nd Edition), Elsevier, and Aguilera, Roberto, Naturally Fractured Reservoirs, PennWell Publishing. The permeability of the shale pore matrix is typically quite low, e.g., in the less than one milliDarcy range. In a shale gas reservoir, this presents a problem because the pore matrix contains most of the hydrocarbons. Since the low permeability of the pore matrix restricts fluid movement, it would be useful to understand how to prompt mass transfer of hydrocarbons from the pore matrix to the fracture network.

Research related to low permeability formations includes Katsube, T. J., “Shale permeability and pore-structure evolution characteristics”, Geological Survey of Canada, Current Research 2000-E15 (2000), which describes several pore structure models, and mercury intrusion and extrusion data. So-called “storage pores” that are dead-ended, but contain fluids, are identified from extrusion data. However, according to Katsube the storage pores do not contribute to the migration of fluids through the rock formation. Imbibition, a process where a wetting fluid spontaneously displaces a non-wetting fluid from a porous medium has long been recognized as an effective means to enhance recovery of oil from low permeability, naturally fractured reservoirs. For example, Hirasaki, G. and Zhang, D., “Surface Chemistry of Oil Recovery From Fractured, Oil-Wet Carbonate Formation”, SPE 80988 (2003) describe capillary pressure and the effects of surface chemistry on imbibition for oil recovery. Penny, G. S., Pursley, J. T., and Clawson, T. D., “Field Study of Completion Fluids to Enhance Gas Production in the Barnett Shale”, SPE 100434 (2006) and Paktinat, J., Pinkhouse, J. A., Williams, C., Clark, G. A., and Penny, G. S., “Field Case Studies: Damage Preventions Through Leakoff Control of Fracturing Fluids in Marginal/Low-Pressure Gas Reservoirs”, SPE 100417 (2006), which are related to stimulation treatments of shales, emphasize water sensitivity and the need to remove water from the well soon after treatments using aqueous fluids. Li, K. and Horne, R. N., “Characterization of Spontaneous Water Imbibition into Gas-Saturated Rocks”, SPE 62552 (2000), provided an early analysis of the process where water is spontaneously imbibed into gas-saturated rocks. The authors note that this process is important to water coning in cases where naturally fractured gas reservoirs are positioned over active aquifers. Experimental results using packs of glass beads and Berea cores showed water imbibition to be a piston-like displacement process. Based upon this observation, the authors formulated a theoretical model that accounts for both effective water permeability and capillary pressure. Generally, the permeability of the media was greater than 500 milli-Darcies (mD). Babadagli, T., Hatiboglu, C. U., “Analysis of counter-current gas-water capillary imbibition transfer at different temperatures”, Journal of Petroleum Science and Engineering 55 (2007) 277-93 describes the counter-current flow phenomenon. The authors speculate that imbibition in gas-liquid systems is different from the case of liquid-liquid systems as might be encountered in oil recovery. Despite a favorable mobility ratio, the authors point out that entrapment of the non-wetting gas phase is likely due to high surface tension. The authors also point out that an efficient matrix-fracture interaction based on the matrix characteristics could be achieved via controllable parameters such as the viscosity and surface tension of the injected fluid. Experiments using Berea cores indicate that less gas trapping occurs when the viscosity and interfacial tension of the imbibing fluid are lowered. The authors note lower surface tension at higher test temperature, e.g., 72.9 dynes/cm at 20 degC vs. 60.8 dynes/cm at 90 degC, and they discuss the effect of lower surface tension. The permeability of the porous media tested by Babadagli et al., a sandstone and a limestone, are 500 and 15 mD respectively, which are 5-6 orders of magnitude greater than the matrix permeability of typical gas shales being developed today.

It is widely believed that water imbibition into a reservoir from a well that will be used for production is deleterious in several ways. See, for example, Bennion, D. B., et al., “Low Permeability Gas Reservoirs: Problems, Opportunities and Solutions for Drilling, Completion, Stimulation and Production,” SPE 35577, Gas Technology Conference, Calgary, Alberta, Canada, April 28-May 1, 1996, and Bennion, D. B., et al., “Formation Damage Processes Reducing Productivity of Low Permeability Gas Reservoirs,” SPE 60325, 2000 SPE Rocky Mountain Regional/Low Permeability Reservoirs Symposium and Exhibition, Denver, Colo., Mar. 12-15, 2000. Imbibed water increases the water saturation and is thought to become trapped and to block hydrocarbon flow. If imbibed water is fresher than formation water, it may affect fresh water sensitive expanding clays. Furthermore, imbibition of water into formations such as shales during drilling may be responsible for spalling and wall collapse. For these reasons, operators often try to complete wells with non-aqueous fluids. Water invasion of reservoirs, except in water-flooding with distinct injectors and producers, is considered a damage mechanism and is to be avoided.

Bennion, et al. (2000) illustrate both the present understanding of one example of how capillary pressures lead to phase trapping of water and to blocking of hydrocarbon production, and give proposed solutions that are opposite the principles and method of the present Invention. Bennion, et al. (2000) teach that very low permeability gas reservoirs are typically in a state of capillary undersaturation, where the initial water (and sometimes oil) saturation is less than would be expected from conventional capillary mechanics for the pore system under consideration. Retention of fluids (phase trapping) is considered to be one of the major mechanisms of reduced productivity, even in successfully fractured completions in these types of formations. In a low permeability gas reservoir, due to the very small size of the pore throats and pore bodies, the tortuous nature of the pore system and the high degree of micro-porosity, the observed radii of curvature of the gas-liquid interfaces are very small, particularly at low water saturations, which gives rise to the higher capillary pressure values and higher irreducible water saturation values which are commonly associated with poor quality porous media. In general, as permeability and porosity decrease and the relative fraction of micro-porosity increases, both the capillary pressure and the irreducible water saturation tend to increase substantially.

Bennion, et al. (2000) further teach that often associated with this increase in trapped initial liquid saturation is a significant reduction in the net effective permeability to gas, caused by the occlusion of a large portion of the pore space by the irreducible and immobile trapped initial liquid saturation present. On a relative permeability basis, in general, the greater the value of the initial trapped fluid saturation, the less original reserves of gas in place are available for production, and also the lower the initial potential productivity of the matrix. In reservoir situations where exceptionally low matrix permeability is present, one finds that, if the reservoir is in a normally saturated condition (that is, if the reservoir is in free contact and capillary equilibrium with mobile water and is at a normal level of capillary saturation for the specific geometry of the porous media under consideration), Bennion, et al. (2000) teach that very high trapped initial liquid saturations tend to be present, and that it can be observed that in reservoir rocks of permeability to gas on an absolute basis of less than 0.1 mD, effective initial water saturations are often in the 60% plus region. This often results in significant reductions of the original reserves of gas in place in the porous media, and may also result in a very low or zero effective permeability to gas, as the gas saturation may be at or near the critical mobile value, and hence it will exhibit limited or no mobility when a differential pressure gradient is applied to the formation during production operations.

Therefore, Bennion, et al. (2000) teach that in most cases where very low permeability gas reservoirs are potentially productive, the reservoir exists in a situation where the reservoir sediments have been isolated from effective continual contact with a free water source which is capable of establishing an equilibrium and uniform capillary transition zone. They believe that a combination of long-term regional migration of gas through the isolated sediments (resulting in an extractive desiccating effect as temperature and pore pressure are increased over geologic time), or an osmotically-motivated suction of connate water into highly hydrophilic clays or overlying/interbedded sentiments, may be responsible for the establishment of what is commonly referred to as a “sub-irreducible” initial water saturation condition.

A reservoir having a sub-irreducible initial water saturation is defined by Bennion, et al. (2000) as a reservoir which exhibits an average initial water saturation less than the irreducible water saturation expected to be obtained for that porous medium at the given column height present in the reservoir above a free water contact (based on a conventional water-gas capillary pressure drainage test). In situations where exceptionally low matrix permeability is present in a gas-producing reservoir, unless a sub-irreducibly saturated original condition is present, the reservoir will exhibit insufficient initial reserves/permeability to be a viable gas-producing candidate. Therefore, Bennion, et al. (2000) believe that, with few exceptions, the vast majority of ultra-low permeability gas reservoirs that would be classified as exhibiting economic gas-producing pay, would fall into this classification of subnormally saturated systems. This phenomenon, they teach, gives rise to one of the most severe potential damage mechanisms in low permeability gas reservoirs: fluid retention or phase trapping.

Bennion, et al. (2000) then teach that “considerable invasion, due to capillary suction effects, can occur when water based fluids are in contact with the formation, even in the absence of a significant overbalance pressure. A phenomena [sic] known as countercurrent capillary imbibition has been well documented in the literature in previous papers and studies by the authors . . . and illustrates how a significant increase in water saturation in the near wellbore or fracture face region can occur in such a situation, even if underbalanced operations are being used when water based fluids (including foams), are circulated in contact with the formation face.” They then propose that this problem can be mitigated by not using water based fluids in drilling, completion, and stimulation. If water based fluids must be used, then they recommend minimizing the exposure time and the depth of water invasion. They then advise that “Capillary pressure, which is the dominant variable controlling fluid retention, is a direct linear function of interfacial tension between the water and gas phase. If this interfacial tension can be reduced between the invading water based filtrate and the in-situ reservoir gas, the magnitude of the capillary pressure and the degree of observed fluid retention may also be lessened.” and they teach that “natural capillary imbibition will want to ‘wick’ or imbibe water from the high water saturation zone (encompassing the original invaded area) deeper into the formation, resulting in a ‘smearing’ of the water saturation profile . . . . As long as a recharge source of unbound water is removed from the wellbore or fracture, this will obviously result in a gradual reduction in the value of the trapped water saturation in the near wellbore or fracture face region, which may result in a slow long term improvement in the permeability to gas in the region which previously exhibited near zero gas permeability.” In other words, Bennion, et al. (2000) advise that availability, let alone injection, of water should be minimized, especially if the interfacial tension has been lowered. This is the exact opposite of the method of the present Invention.

SUMMARY OF THE INVENTION

The Invention is predicated in part on recognition that in low permeability sources the conditions which favor release of oil due to imbibition differ from the conditions which favor release of gas due to imbibition. Further, the interfacial tension between oil and water is much lower than the interfacial tension between a gaseous phase and water. In accordance with an embodiment of the Invention, a method for enhancing hydrocarbon recovery from a low permeability source comprises: causing treating fluid to contact the source such that the treating fluid is imbibed by the source, thereby increasing hydrocarbon recovery. In accordance with another embodiment of the Invention, apparatus for enhancing hydrocarbon recovery from a low permeability source comprises a container that stores a treating fluid. The container may be, but is not limited to, a stationary tank, mobile tank/trailer, earthen pit, lake, river, or any other source where fluid may be drawn from. The treating fluid may also be pre-mixed or all additives added continuously on-the-fly as will be known to those knowledgeable of such treatments. The treating fluid is characterized by constituents that facilitate imbibition. The apparatus also includes a fluid transfer device that transfers the treating fluid from the container to the source and a conduit that recovers hydrocarbons released from the source due to imbibition of the treating fluid.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 illustrates apparatus for recovering hydrocarbons from a low permeability source in accordance with an embodiment of the Invention.

FIG. 2 illustrates a method for formulating the treating fluid.

FIG. 3 illustrates an example of how different treating fluids interact with a reservoir.

FIG. 4 illustrates differences in gas recovery for treating fluids having different formulations, specifically, different surfactants, for a given shale reservoir sample.

DETAILED DESCRIPTION

FIG. 1 illustrates apparatus for enhancing recovery of hydrocarbons (in this example gas 100) from a low permeability hydrocarbon reservoir 102. The apparatus utilizes a borehole 103 which is formed by drilling through various layers of rock (collectively, overburden 104), if any, to the low permeability reservoir. The reservoir will be described as a shale reservoir. However, the Invention is not limited to shale reservoirs. For example, the reservoir may be of any type characterized by low permeability. Further, it is believed that the technique can practically be applied to any reservoirs having low matrix permeability (i.e. between 100 nano-Darcies (nD) and 500 mD, where 1 D=9.87×10⁻¹³ m²).

For gas and/or supercritical fluid producing wells, the technique is particularly advantageous when the matrix permeability is less than 10 mD, even more advantageous when the matrix permeability is less than 5 mD, and most advantageous when the matrix permeability is less than 1 mD. The term “gas” means a collection of primarily hydrocarbon molecules without a definite shape or volume that are in more or less random motion, have relatively low density and viscosity, will expand and contract greatly with changes in temperature or pressure, and will diffuse readily, spreading apart in order to homogeneously distribute itself throughout any container. The term “supercritical fluid” means any primarily hydrocarbon substance at a temperature and pressure above its thermodynamic critical point, that can diffuse through solids like a gas and dissolve materials like a liquid, and has no surface tension, as there is no liquid/gas phase boundary.

For oil and/or condensate producing wells, the technique is particularly advantageous when the matrix permeability is less than 500 mD, even more advantageous when the matrix permeability is less than 250 mD, and most advantageous when the matrix permeability is less than 100 mD. The term “oil” means any naturally occurring, flammable or combustable liquid found in rock formations, typically consisting of mixture of hydrocarbons of various molecular weights plus other organic compounds such as is defined as any hydrocarbon, including for example petroleum, gas, kerogen, paraffins, asphaltenes, and condensate. The term “condensate” means a low-density mixture of primarily hydrocarbon liquids that are present as gaseous components in raw natural gas and condense out of the raw gas when the temperature is reduced to below the hydrocarbon dew point temperature of the raw gas.

The recovery enhancing apparatus may include a fluid storage tank 106, a pump 108, a well head 110, and a gas recovery flowline 112. The fluid tank 106 contains a treating fluid formulated to promote imbibition in the low permeability reservoir. For example, the treating fluid may be an aqueous solution including surfactants that result in a surface tension adjusted to optimize imbibition based at least in part on determination or indication of the wettability of the shale, permeability of the shale, or both. The treating fluid 114 is transferred from the tank to the borehole using the pump 108, where the treating fluid comes into contact with the reservoir. The physical characteristics of the treating fluid facilitate migration of the treating fluid into the shale reservoir. In particular, the treating fluid enters the pore space when exposed to the reservoir, e.g., for hours, days, weeks, or longer. Entrance of the treating fluid into the pore space tends to displace gas from the pore space. The displaced gas migrates from the reservoir 116 to the borehole 103 through the pore space, via the network of natural and/or induced fractures. Within the borehole, the gas moves toward the surface as a result of differential pressure (lower at the surface and higher at the reservoir) and by having a lower density than the treating fluid. The gas is then recovered via the pipe (flowline) at the wellhead. The recovered gas is then transferred directly off site, e.g., via flowline 112.

The principle of operation of the treating fluid is based on capillary pressure. In particular, capillary pressure facilitates imbibition of the treating fluid and displacement of the gas. Capillary pressure can be calculated by the following equation:

${P_{c} = \frac{2\; \gamma \; \cos \; \theta}{r}},{where}$

-   -   γ represents interfacial tension, θ represents contact angle,         and r represents pore radius. As already described, shales         exhibit very low matrix permeability. A shale sample exhibiting         a matrix permeability of 500 nD may have an average pore radius         of only about 2×10⁻⁸ cm. Substituting example values for the         interfacial tension, contact angle and pore radius into the         equation above yields a capillary pressure in excess of 72,000         kPa, or 10,440 psi. Increasing the contact angle to 60 degrees         yields a capillary pressure of 5,220 psi. The capillary pressure         causes imbibition of the treating fluid into the shale pore         space. Imbibition into either a closed capillary or an infinite         capillary results in co-current or counter-current flow, i.e.,         total flux is zero. Further, co-current or counter-current         imbibition will occur when an element of the matrix is         completely surrounded by wetting fluid.

It should be noted that capillary pressure is defined as the difference between the pressures in the wetting and non-wetting fluids. Consequently, the imbibition of the treating fluid will be spontaneous and independent of any positive applied differential pressure.

FIG. 2 illustrates a method for calculating the constituents of the treating fluid. The method includes a first preparatory step 200 of estimating capillary size and/or permeability. Estimation of permeability may be based on examination of samples using standard laboratory techniques as shown in step 208, or assumptions based on pre-existing data or experience (collectively, assumptions 206).

A second preparatory step 202 is estimating formation wettability. Wettability is an indication of the tendency of a fluid to spread on the surface of a substance. At one extreme of wettability the fluid responds to a solid so as to maximize the surface area of the interface between the fluid and solid. At another extreme of wettability the fluid forms a ball, thereby minimizing the interfacial area. Estimation of wettability may be based on examination of samples using standard laboratory techniques, as indicated in step 210, assumptions based on pre-existing data or experience (collectively, assumptions 212), or contact angle measurement 214. The contact angle is the angle, measured through the liquid, formed between the surface of a drop of fluid and the surface of the substance upon which the drop is placed. If the drop readily wets the surface, then the static contact angle will be relatively small. Conversely, if the drop doesn't wet the surface, it will form a bead and the static contact angle will be large. Shales typically exhibit mixed wettability; i.e. they are not completely 100% oil- or water-wet, although this is not to say that they cannot be. Table 1 shows the relationship between wettability and contact angle (static measurement). Given a shale sample that is strongly water-wet, a treating fluid may be formulated such that the contact angle formed between treating fluid and the shale matrix approaches 0 degrees.

TABLE 1 Relationship between static contact angle and wettability Contact Angle Wettability 0°-70° Strongly water-wet 70°-110° Intermediate wettability 110°-180°  Strongly oil-wet

The estimation of wettability is used to determine constituent ingredients (e.g., surfactants) of the treating fluid as shown in step 204. Correlations can then be used to determine the type and concentration of surfactant to be used to achieve enhanced gas recovery. It may also be desirable to include anti-bacterial agents to inhibit growth that would compromise the overall effectiveness of the process. Other constituents may also be selected, including but not limited to scale inhibitors, formation stabilizers, e.g., fines stabilizers and clay stabilizers, oxygen scavengers, antioxidants, iron control agents, corrosion inhibitors, emulsifiers, demulsifiers, foaming agents, anti-foaming agents, buffers, pH adjusters and additives that will alter the available surface area, e.g., by chemical means including but not limited to oxidation and sulfonation.

FIG. 3 illustrates an example of how different treating fluids interact with a formation sample. The example is based on black shale formation samples. The treating fluids for this example are water and toluene. Note that the data can be used to determine a quantitative measure of the contact angle, i.e. after a measurement of the permeability of various pack and fluid properties.

FIG. 4 illustrates differences in gas recovery for wetting fluids having different formulations, specifically, different surfactants, for a given shale reservoir sample. The data show that recovery from “un-treated” cores is significantly less than recovery from “treated” cores, where treatment refers to the use of surfactant in the treating fluid. It should be noted that the un-treated cores yield far lower ultimate gas recovery.

A variation of the technique described above is to delay the release (e.g., by encapsulation, solubility, etc.) of the surfactant altering the wettability in order to reduce or eliminate phase-trapping. Another variation is to use surfactants where the hydrophilic-lipophilic balance (HLB) changes with temperature.

It should be noted that although the Invention has been described with respect to recovery of hydrocarbon from a source, it is envisioned that the Invention could also be applied to a source that is obtained via mining operations, e.g., surface mining. For example, material obtained from surface mining could be treated with fluid to recover or remove hydrocarbon from the material, such as overburden removed during coal mining operations.

While the Invention is described through the above exemplary embodiments, it will be understood by those of ordinary skill in the art that modification to and variation of the illustrated embodiments may be made without departing from the inventive concepts herein disclosed. Moreover, while the preferred embodiments are described in connection with various illustrative structures, one skilled in the art will recognize that the system may be embodied using a variety of specific structures. Accordingly, the Invention should not be viewed as limited except by the scope and spirit of the appended claims. 

1. A method for enhancing hydrocarbon recovery from a low permeability source comprising: causing a treating fluid to contact the source such that the treating fluid is imbibed by the source, thereby increasing hydrocarbon recovery, wherein the source is characterized by matrix permeability less than 0.2 milliDarcies (mD).
 2. The method of claim 1, further comprising: estimating source wettability; determining constituents of said treating fluid based on said estimated source wettability; formulating said treating fluid using said determined constituents.
 3. The method of claim 1 wherein estimating source wettability includes estimating a contact angle.
 4. The method of claim 1 wherein the recovered hydrocarbon comprises a gas or a supercritical fluid.
 5. The method of claim 4 wherein said source has a reservoir matrix permeability of less than 0.1 mD.
 6. The method of claim 1 wherein the recovered hydrocarbon comprises an oil or a condensate.
 7. The method of claim 6 wherein said source has a reservoir matrix permeability of less than 0.01 mD.
 8. The method of claim 1 wherein determining treating fluid constituents includes selecting at least one constituent selected from the group which includes scale inhibitors, formation stabilizers, e.g., fines stabilizers and clay stabilizers, oxygen scavengers, antioxidants, iron control agents, corrosion inhibitors, emulsifiers, demulsifiers, foaming agents, anti-foaming agents, buffers, pH adjusters and other additives that will alter the available surface area.
 9. The method of claim 8 including determining a surfactant type and concentration to achieve the desired imbibition in order to increase hydrocarbon recovery.
 10. The method of claim 1 wherein said treating fluid includes an anti-bacterial or biocidal agent.
 11. The method of claim 1 wherein said treating fluid includes a constituent that results in surface tension of said treating fluid changing over time.
 12. The method of claim 1 wherein said treating fluid includes a constituent that causes surface tension of said treating fluid to change in response to a temperature change.
 13. The method of claim 1, wherein said treating fluid is placed into contact with the source and hydrocarbon is recovered through the same wellbore.
 14. The method of claim 1, wherein said treating fluid is placed into contact with the source and hydrocarbon is recovered through different wellbores.
 15. Apparatus for enhancing hydrocarbon recovery from a low permeability source comprising: a container that stores a treating fluid, said treating fluid characterized by one or more constituents that facilitate imbibition; a fluid transfer device that transfers said treating fluid from said container to the source; and a conduit that recovers hydrocarbons released from the source due to imbibition of said treating fluid, wherein the source is characterized by matrix permeability less than 0.2 milliDarcies (mD).
 16. An apparatus in accordance with claim 15, wherein said treating fluid comprises one or more constituents selected based on estimates of source wettability.
 17. The apparatus of claim 15 wherein the estimate of source wettability includes an estimate of contact angle.
 18. The apparatus of claim 15 wherein the recovered hydrocarbon comprises a gas or a supercritical fluid.
 19. The apparatus of claim 18 wherein said source has a reservoir matrix permeability of less than 0.1 mD.
 20. The apparatus of claim 15 wherein the recovered hydrocarbon comprises an oil or a condensate.
 21. The apparatus of claim 20 wherein said source has a reservoir matrix permeability of less than 0.01 mD.
 22. The apparatus of claim 15 wherein said treating fluid includes at least one constituent selected from the group which includes scale inhibitors, source stabilizers, and surface area modifiers.
 23. The apparatus of claim 15 wherein said treating fluid includes at least one surfactant having a type and concentration required to achieve improved hydrocarbon recovery.
 24. The apparatus of claim 15 wherein the treating fluid includes an anti-bacterial or biocidal agent.
 25. The apparatus of claim 23 wherein the treating fluid includes a constituent that results in the surface tension changing over time.
 26. The apparatus of claim 23 wherein the treating fluid includes a constituent that causes surface tension to change in response to a temperature change.
 27. The apparatus of claim 15, wherein said treating fluid is transferred and said hydrocarbon is recovered through the same wellbore.
 28. The apparatus of claim 15, wherein said treating fluid is transferred and said hydrocarbon is recovered through different wellbores. 